Use of nano-sized phyllosilicate minerals in viscoelastic surfactant fluids

ABSTRACT

Nano-sized clay minerals enhance the viscosity of aqueous fluids that have increased viscosity due to the presence of viscoelastic surfactants (VESs). In one non-limiting theory, the nano-sized phyllosilicate mineral viscosity enhancers associate, link, connect, or relate the VES elongated micelles into associations thereby increasing the viscosity of the fluid, possibly by mechanisms involving chemisorption or surface charge attractions. The nano-sized phyllosilicate mineral particles, also called clay mineral nanoparticles, may have irregular surface charges. The higher fluid viscosity is beneficial to crack the formation rock during a fracturing operation, to reduce fluid leakoff, and to carry high loading proppants to maintain the high conductivity of fractures.

CROSS-REFERENCE TO RELATED APPLICATION

This application is a continuation-in-part application from U.S. Ser.No. 11/755,549 filed on May 30, 2007, now abandoned.

TECHNICAL FIELD

The present invention relates to aqueous, viscoelastic fluids usedduring hydrocarbon recovery operations, and more particularly relates,in one embodiment, to methods and additives for increasing the viscosityof fluids gelled with viscoelastic surfactants.

BACKGROUND

Hydraulic fracturing is a method of using pump rate and hydraulicpressure to fracture or crack a subterranean formation. Once the crackor cracks are made, high permeability proppant, relative to theformation permeability, is pumped into the fracture to prop open thecrack. When the applied pump rates and pressures are reduced or removedfrom the formation, the crack or fracture cannot close or healcompletely because the high permeability proppant keeps the crack open.The propped crack or fracture provides a high permeability pathconnecting the producing wellbore to a larger formation area to enhancethe production of hydrocarbons.

The development of suitable fracturing fluids is a complex art becausethe fluids must simultaneously meet a number of conditions. For example,they must be stable at high temperatures and/or high pump rates andshear rates which can cause the fluids to degrade and prematurely settleout the proppant before the fracturing operation is complete. Variousfluids have been developed, but most commercially used fracturing fluidsare aqueous based liquids which have either been gelled or foamed. Whenthe fluids are gelled, typically a polymeric gelling agent, such as asolvatable polysaccharide is used, which may or may not be crosslinked.The thickened or gelled fluid helps keep the proppants within the fluidduring the fracturing operation.

While polymers have been used in the past as gelling agents infracturing fluids to carry or suspend solid particles in the brine, suchpolymers require separate breaker compositions to be injected to reducethe viscosity. Further, the polymers tend to leave a coating on theproppant even after the gelled fluid is broken, which coating mayinterfere with the functioning of the proppant. Studies have also shownthat “fish-eyes” and/or “microgels” present in some polymer gelledcarrier fluids will plug pore throats, leading to impaired leakoff andcausing formation damage. Conventional polymers are also either cationicor anionic which present the disadvantage of likely damage to theproducing formations.

Aqueous fluids gelled with viscoelastic surfactants (VESs) are alsoknown in the art. Certain surfactants in particular proportions andconditions will self-assemble into micelles. When the micelles areelongated or “rod-like”, their entanglement increases viscosity of thefluid in which they reside. VES-gelled fluids have been widely used asgravel-packing, frac-packing and fracturing fluids because they exhibitexcellent rheological properties and are less damaging to producingformations than crosslinked polymer fluids. VES fluids arenon-cake-building fluids, and thus leave no potentially damaging polymercake residue.

However, the same property that makes VES fluids less damaging tends toresult in significantly higher fluid leakage into the reservoir matrix,which reduces the efficiency of the fluid especially during VESfracturing treatments. Increasing the viscosity of the VES-gelled fluidswould reduce their tendency to leak into the formation. Thus, it wouldbe desirable if methods or additives were developed to enhance orincrease the viscosity of the VES-gelled fluids.

SUMMARY

There is provided, in one form, a method for treating a subterraneanformation that involves providing an aqueous viscoelastic treating fluidwhich includes an aqueous base fluid or brine, a viscoelastic surfactant(VES) gelling agent, and a phyllosilicate mineral particle viscosityenhancer. The VES gelling agent is present in an amount effective toincrease the viscosity of the aqueous base fluid by forming elongatedmicelles. Suitable phyllosilicate mineral particle viscosity enhancersinclude, but are not limited to, montmorillonites, bentonites,kaolinites, smectites, chlorites, illites, mixed layer clays of theforegoing identified clays, and mixtures thereof. The aqueousviscoelastic surfactant treating fluid is injected the through awellbore and into the subterranean formation, and the subterraneanformation is thus treated by the fluid. The phyllosilicate particles mayhave an average particle size between about 1 and about 1000 nanometers,or less than 1000 nm. The phyllosilicate mineral particle viscosityenhancer is present in an amount effective to improve viscosity of thefluid as compared with an identical fluid absent the clay mineralparticle viscosity enhancer by associating the micelles together in anassociation

There is further provided in another non-limiting embodiment an aqueousviscoelastic treating fluid that includes an aqueous base fluid orbrine, a viscoelastic surfactant (VES) gelling agent, and a clay mineralviscosity enhancer that again may include montmorillonites, kaolinites,smectites, chlorites, illites, mixed layer clays of the foregoing clayminerals, and mixtures thereof. Once more, the VES gelling agent ispresent in an amount effective to increase the viscosity of the aqueousbase fluid by forming elongated micelles. The clay mineral particleviscosity enhancer has an average particle size ranging from about 1 toabout 1000 nanometers, and is present in an amount effective to improveviscosity of the fluid as compared with an identical fluid absent thenano-sized clay phyllosilicate mineral particle viscosity enhancer byassociating the micelles together in an association. The “clay mineralparticle viscosity enhancer” is also termed herein “nano-sizedphyllosilicate mineral”, and these terms should be considered the sameand interchangeable.

The nano-sized clay mineral viscosity enhancers appear to help enhancethe fluid viscosity and develop a pseudo-filter cake of VES micelles byassociating with them as well as ions and particles to produce a noveland unusual viscous fluid layer of pseudo-crosslinked elongated micelleson the reservoir face that limits further VES fluid leak-off.Additionally, the art may be further advanced by use of viscosityenhancers that also form a similar viscous fluid layer ofpseudo-crosslinked micelles on the formation face effective incontrolling the rate of VES fluid loss, yet can be less pore plugging ornon-pore plugging and physically easier to produce back with the VESfluid after a VES treatment, as compared to using polymers. That is, theeffectiveness of the method is largely independent of the size of theviscosity enhancers.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a graph of the viscosity over time of two viscoelastic brinefluids containing, one of which has 10 pptg (1.2 kg/m³) montmorillonitenano-sized clay particles, and one which does not;

FIG. 2 is a graph of fluid leakoff in milliliters as a function of timefor two viscoelastic brine fluids, where one does not contain anano-sized clay mineral, and an otherwise identical fluid that contains20 pptg (2.4 kg/m³) montmorillonite nano-sized clay particles;

FIG. 3 is a photograph of a viscous layer of pseudo-filter cake; and

FIG. 4 is another photograph of a pseudo-filter cake built on a 400 mDceramic disc.

DETAILED DESCRIPTION

It has been discovered that the addition of nano-sized phyllosilicatemineral particles to an aqueous VES fluid demonstrates improved,enhanced or increased viscosity of the VES fluid. The viscosityenhancers herein are believed to be particularly useful in VES-gelledfluids used for well completion or stimulation and other uses andapplications where the viscosity of VES-gelled aqueous fluids may beincreased. The VES-gelled fluids may further comprise proppants orgravel, if they are intended for use as fracturing fluids or gravelpacking fluids, respectively, although such uses do not require that thefluids include proppants or gravel in some embodiments. It is especiallyuseful that the phyllosilicate viscosity enhancer particles are verysmall, which permits their removal from the formation to be easy andcomplete causing little or no damage to the formation.

In one non-limiting explanation or theory, the nano-sized phyllosilicatemineral particles have or bear electrical charges on their surfaces,possibly due to their irregular crystal structures. The particles withsurface charges associate, connect or link the VES micelles, thusfurther increasing their 3-D network and enhancing the viscosity of thefluid system. In one non-limiting explanation, chemisorption and/orsurface charge attraction are believed to be mechanisms involved in theVES micelle association. It is this VES micelle association structure,sometimes called “pseudo-crosslinked”, that is believed to enhance theviscosity of the gelled aqueous viscoelastic treating fluid. Such clayparticles are believed to work at elevated temperatures. In particular,the VES-gelled aqueous fluids have improved (increased, enhanced orraised) viscosity over a broad range of temperatures, such as from about70 (about 21° C.) to about 400° F. (about 204° C.); alternatively up toabout 350° F. (about 177° C.), and in another non-limiting embodiment upto about 300° F. (about 149° C.).

This discovery allows the VES system to have improved fluid viscosityand reduced fluid loss to help minimize formation damage during wellcompletion or stimulation operations. That is, the introduction of thesenano-sized clay mineral viscosity enhancers to the VES-gelled aqueoussystem will limit and reduce the amount of VES fluid which leaks-offinto the pores of a reservoir during a fracturing or frac-packingtreatment, thus minimizing the formation damage that may occur by theVES fluid within the reservoir pores. Also, limiting the amount of VESfluid that leaks-off into the reservoir during a treatment will allowmore fluid to remain within the fracture and thus less total fluidvolume will be required for the treatment. Having less fluid leaking-offand more fluid remaining within the fracture will enable greaterfracture size and geometry to be generated. Enhancing the fluidviscosity of the VES-gelled fluids also helps reduce the amount of VESnecessary to achieve a particular viscosity level. Thus, the use ofthese nano-sized phyllosilicate mineral viscosity enhancers in aVES-gelled aqueous system may improve the performance of the VES fluidwhile lowering fracturing treatment cost.

Prior art VES-gelled aqueous fluids, being non-wall-building fluids(i.e. there is no polymer or similar material build-up on the formationface to form a filter cake) that do not build a true filter cake on theformation face, have viscosity controlled fluid leak-off into thereservoir. By contrast, the methods and compositions herein use anano-sized phyllosilicate mineral viscosity enhancer that is believed toassociate with the VES micelle structures through particle surfacecharge attraction, allowing pseudo-crosslinking of the elongatedmicelles to occur, in one non-limiting explanation of the mechanisms atwork herein. This unique association of elongated micelles has beenfound to form a highly viscous layer of crosslinked-like VES fluid onthe formation face, thus acting as a pseudo-filter cake layer thatlimits, inhibits and controls additional VES fluid from leaking-off intothe reservoir pores (see FIGS. 3 and 4). The pseudo-filter cake iscomposed of VES micelles that have VES surfactants with very lowmolecular weights of less than 1000. This is in contrast to anddifferent from polymeric fluids that form true polymer massaccumulation-type filter cakes by having very high molecular weightpolymers (1 to 3 million molecular weight) that due to their size arenot able to penetrate the reservoir pores, but bridge-off and restrictfluid flow in the pores.

The nano-sized clay mineral viscosity enhancers herein associate withthe VES micelles and as VES fluid is leaked-off into the reservoir aviscous layer or association of micelles and viscosity enhancerparticles and/or ions accumulate on the formation face, thus reducingthe rate of VES fluid leak-off. It has been discovered that particulateplugging of the reservoir pores may not be the mechanism of leak-offcontrol or the mechanism that allows development of the viscous micellelayer. Tests using nanometer-sized clay mineral viscosity enhancerparticles (on the order of 10⁻⁹ to 10⁻⁸ meters), that have no potentialto bridge or plug reservoir pores of 0.1 mD or higher reservoirpermeability, develop the viscous micelle layer.

In the method of the invention, an aqueous fracturing fluid, as anon-limiting example, is prepared by blending a VES into an aqueousfluid. The aqueous base fluid could be, for example, water, brine,aqueous-based foams or water-alcohol mixtures. The brine base fluid maybe any brine, conventional or to be developed which serves as a suitablemedia for the various concentrate components. As a matter ofconvenience, in many cases the brine base fluid may be the brineavailable at the site used in the completion fluid, in a non-limitingexample.

The aqueous fluids gelled by the VESs herein may optionally be brines.In one non-limiting embodiment, the brines may be prepared using saltsincluding, but not necessarily limited to, NaCl, KCl, CaCl₂, MgCl₂,NH₄Cl, CaBr₂, NaBr, sodium formate, potassium formate, and othercommonly used stimulation and completion brine salts. The concentrationof the salts to prepare the brines may be from about 0.5% by weight ofwater up to near saturation for a given salt in fresh water, such as10%, 20%, 30% and higher percent salt by weight of water. The brine maybe a combination of one or more of the mentioned salts, such as a brineprepared using NaCl and CaCl₂ or NaCl, CaCl₂, and CaBr₂ as non-limitingexamples.

The viscoelastic surfactants suitable for use in this invention include,but are not necessarily limited to, non-ionic, cationic, amphoteric, andzwitterionic surfactants. Specific examples of zwitterionic/amphotericsurfactants include, but are not necessarily limited to, dihydroxylalkyl glycinate, alkyl ampho acetate or propionate, alkyl betaine, alkylamidopropyl betaine and alkylimino mono- or di-propionates derived fromcertain waxes, fats and oils. Quaternary amine surfactants are typicallycationic, and the betaines are typically zwitterionic. The thickeningagent may be used in conjunction with an inorganic water-soluble salt ororganic additive such as phthalic acid, salicylic acid or their salts.

Some non-ionic fluids are inherently less damaging to the producingformations than cationic fluid types, and are more efficacious per poundthan anionic gelling agents. Amine oxide viscoelastic surfactants havethe potential to offer more gelling power per pound, making it lessexpensive than other fluids of this type.

The amine oxide gelling agents RN⁺(R′)₂O⁻ may have the followingstructure (I):

where R is an alkyl or alkylamido group averaging from about 8 to 24carbon atoms and R′ are independently alkyl groups averaging from about1 to 6 carbon atoms. In one non-limiting embodiment, R is an alkyl oralkylamido group averaging from about 8 to 16 carbon atoms and R′ areindependently alkyl groups averaging from about 2 to 3 carbon atoms. Byindependently it is meant that each R′ may be the listed possibilitiesand need not be the same as the other. In an alternate, non-restrictiveembodiment, the amine oxide gelling agent is tallow amido propylamineoxide (TAPAO), which should be understood as a dipropylamine oxide sinceboth R′ groups are propyl.

Materials sold under U.S. Pat. No. 5,964,295 include ClearFRAC™ whichmay also comprise greater than 10% of a glycol. This patent isincorporated herein in its entirety by reference. One preferred VES isan amine oxide. As noted, a particularly preferred amine oxide is tallowamido propylamine oxide (TAPAO), sold by Baker Hughes as SurFRAQ™ VES.SurFRAQ is a VES liquid product that is 50% TAPAO and 50% propyleneglycol. These viscoelastic surfactants are capable of gelling aqueoussolutions to form a gelled base fluid. The additives of this inventionmay also be used in Diamond FRAQ™ which is a VES system, similar toSurFRAQ, which contains VES breakers sold by Baker Hughes.

The amount of VES included in the fracturing fluid depends on twofactors. One involves generating, creating or producing enough viscosityto control the rate of fluid leak off into the pores of the fracture,which is also dependent on the type and amount of fluid loss controlagent and/or nano-sized clay particle viscosity enhancer used, and thesecond involves creating, generating or producing a viscosity highenough to develop the size and geometry of the fracture within thereservoir for enhanced reservoir production of hydrocarbons and to alsokeep the proppant particles suspended therein during the fluid injectingstep, in the non-limiting case of a fracturing fluid. Thus, depending onthe application, the VES is added to the aqueous fluid in concentrationsranging from about 0.5 to 12.0% by volume of the total aqueous fluid (5to 120 gallons per thousand gallons (gptg)). In another non-limitingembodiment, the range for the compositions and methods herein is fromabout 1.0 independently to about 6.0% by volume VES product. In analternate, non-restrictive form, the amount of VES ranges from 2independently to about 10 volume %. The term “independently” when usedherein with respect to parameter ranges means that any lower thresholdmay be used together with any upper threshold to give a suitablealternative range.

The viscosity enhancers useful herein include, but are not necessarilylimited to, nano-sized natural and synthetic phyllosilicate clay mineralviscosity enhancers. In one non-limiting embodiment the clay particlesmay have an average particle size of 1000 nanometers or less, in partfor assurance that they are less pore plugging or non-pore pluggingparticles, that is, substantially reduced or not damaging to theformation that the fluid contacts. Nano-scale particles are easier toflow in and out of underground porous media and less prone to plug flowchannels of oil and gas. The clay particles may also be packaged orcomposed as a slurry product for ease of addition and salts may bepresent in the slurry as dispersants to prevent clay flocculation duringcommercial storage and used within VES fluids.

The chemisorption and/or surface charge character of the phyllosilicateclay particles is believed to vary widely, allowing for a wide range ofcharged surface submicron or nano-sized particles to select from formodifying the properties of VES gelled aqueous fluids. Thus, it isexpected that more than one nano-sized clay particle type may be mixedtogether, and possibly also with pyroelectric and/or piezoelectricparticles to tailor the viscosity enhancers to the needs of the system.Suitable phyllosilicate minerals, natural and synthetic, may include,but are not necessarily limited to, montmorillonites, bentonites,kaolinites, smectites, chlorites, illites, mixed layer clays of theforegoing clay minerals, and the like and mixtures thereof. The surfacecharges of the clay particles are believed to come from ionicsubstitutions in the tetrahedral and/or octahedral sheet crystalstructures and/or surface defects, and thus the particles may be said tohave ionic surfaces.

In another non-restrictive embodiment, the surface of the clay particlesshould have a cation exchange capacity (CEC) that attracts positivelycharged ions. It is not necessary for the clay particles to have highCEC and surface charge (although they may be), but having this abilityis an indicator that the clay may function as a suitable viscosityenhancer. In one non-limiting example, the clay surface may be modified,either partially or completely, such as made partially or completelyhydrophobic by the addition of or treatment with a quaternary aminesurfactant to the clay. The more quaternary amine surfactant used tomodify the clay surface, the more hydrophobic the clay surface willbecome. By the term “completely hydrophobic” is meant that the surfacecannot be made more hydrophobic beyond that point. Additionally, theclay surfaces may also be modified using surface active agents besidessalinity (i.e. agents containing Ca, Mg, Na, K and the like), such assiloxanes, sulfonates, sorbitan esters, fatty acids, and the like, innon-restrictive examples.

In one non-limiting explanation, when the VES fluid mixed with verysmall phyllosilicate mineral particles, such as nano-sizedmontmorillonite, is pumped downhole into underground formations thesurface charges present permit the clay particles to associate, link,connect or otherwise relate the VES micelles together to increase fluidviscosity. The association or relation of the elongated micelles isthought to be roughly analogous to the crosslinking of polymer moleculesby crosslinkers. The high fluid viscosity is helpful and beneficial tocrack the formation rock (such as in a fracturing operation), reducefluid leakoff and carry high loadings of proppants to maintain the highconductivity of the fractures. After the fracturing job is done, in onenon-limiting embodiment, the internal breakers in the VES fluid breakthe VES micelles and the nano-sized clay particles flow back with theproducing fluids. Very little or no formation damage is expected fromthe use of the nano-sized viscosity enhancer particles.

In another non-limiting embodiment, the viscosity enhancers herein donot include the suspension of colloidal particles employed in U.S. Pat.No. 7,081,439. More specifically, the viscosity enhancers herein do notinclude colloidal particles comprising a material selected from thegroup consisting of silica, aluminum oxide, antimony oxide, tin oxide,cerium oxide, yttrium oxide and zirconium oxide, nor mica. In anothernon-limiting embodiment, the gelled aqueous viscoelastic treating fluidhas an absence of added silica prior to its injecting through a wellboreand into a subterranean formation. While silica may become present inthe gelled aqueous viscoelastic treating fluid from outside sources,such as the subterranean formation itself, no silica is intentionallyadded to the fluid.

In one non-restrictive embodiment, the amount of clay mineral viscosityenhancer ranges from about 0.1 to about 500 pounds per thousand gallons(pptg) (about 0.012 to about 60 kg/m³) based on the aqueous viscoelastictreating fluid.

In another non-restrictive embodiment, the amount of viscosity enhancermay have a lower limit of about 0.5 pptg (about 0.06 kg/m³) andindependently an upper limit of about 100 pptg (about 12 kg/m³) or 200pptg (about 24 kg/m³), and in another non-restrictive version a lowerlimit of about 1 pptg (about 0.12 kg/m³) and independently an upperlimit of about 50 pptg (about 6 kg/m³), and in still anothernon-limiting embodiment, a lower limit of about 2 pptg (about 0.2 kg/m³)and independently an upper limit of about 20 pptg (about 2.4 kg/m³).

In another non-limiting embodiment, the average particle size of theviscosity enhancers ranges between about 1 nanometer independently up toabout 1000 nanometers; alternatively less than 1000 nanometers, and inanother non-restrictive version from about 10 nanometers independentlyup to about 500 nanometers. For instance, an average particle size rangeof from 15 nanometers independently up to about 250 nanometers wouldalso be suitable.

It turns out that the particle size distribution of the viscosityenhancer is probably not a major factor for increasing viscosity andfluid loss control in VES-gelled fluids. In one non-limitingexplanation, it appears that the clay particles have negative charges onthe surface thereof due to their crystal structure defects. Thesenegative charges will attract the cationic part in the micelle ofVES-gelled fluids and form a relatively strong 3D micellar-particlenetwork that increases fluid viscosity and limits fluid flow into thepore throats of porous formation to reduce the VES fluid loss. Thesurface charges of viscosity enhancer particles associating with themicelles of VES-gelled fluids form an association, e.g. a viscous layeror a pseudo-filter cake on the rock surface to block fluid flowing intothe rock. Another advantage for the clay particles being a goodviscosity enhancer in VES-gelled fluids is that they are sufficientlysmall and may be easily removed during production; therefore, minimizingformation damage that can occur as compared with other known fluid losscontrol additives or systems.

In hydraulic fracturing applications, propping agents are typicallyadded to the base fluid after the addition of the VES. The proppants,solid particles or gravel may be any solid particulate matter suitablefor its intended purpose, for example as a screen or proppant, etc.Propping agents include, but are not limited to, for instance, quartzsand grains, glass and ceramic beads, bauxite grains, walnut shellfragments, aluminum pellets, nylon pellets, sized calcium carbonate,other sized salts, and the like. The propping agents are normally usedin concentrations between about 1 to 14 pounds per gallon (120-1700kg/m³) of fracturing fluid composition, but higher or lowerconcentrations may be used as the fracture design requires. The basefluid can also contain other conventional additives common to the wellservice industry such as water wetting surfactants, non-emulsifiers andthe like. In the compositions and methods herein, the base fluid mayalso contain additives which can contribute to breaking the gel(reducing the viscosity) of the VES fluid, also known as internalbreakers. External breakers added separately may also be used, but aregenerally less advantageous.

While the viscoelastic fluids of the invention are described mosttypically herein as having use in fracturing fluids, it is expected thatthey will also find utility in completion fluids, gravel pack fluids,fluid loss pills, lost circulation pills, diverter fluids, foamedfluids, stimulation fluids and the like.

In another embodiment of the invention, the treatment fluid may containother viscosifying agents, other different surfactants, claystabilization additives, scale dissolvers, biopolymer degradationadditives, and other common and/or optional components.

In a more preferable embodiment of the methods and compositions herein,use with internal VES breakers can have synergistic clean-up effects forthe viscosity enhancers and the VES fluid. Use of the viscosityenhancers herein with an internal breaker may allow less VES fluid toleak-off into the reservoir, thus resulting in less fluid needed to bebroken and removed once the treatment is over. Additionally, use of aninternal breaker within the VES micelles may further enhance thebreaking and removal of the pseudo-filter cake viscous VES layer thatdevelops on the formation face with the viscosity enhancers of thisinvention. Lab tests to date appear to show that the viscous VESpseudo-filter cake has the micelles readily broken down to therelatively non-viscous, more spherically-shaped micelles by use of aninternal breaker, and also with use of an encapsulated breaker, ifemployed.

In an optional embodiment, the aqueous viscoelastic treating fluidherein has an absence of scale resistant proppants such as thosedescribed in U.S. Patent Application Publication No. 2006/0272816,incorporated by reference herein in its entirety. Further, unlike thesubstrates discussed in U.S. Patent Application Publication No.2006/0272816 which are taught as being inert to components in thesubterranean formation such as well treatment fluids, the clay mineralparticle viscosity enhancers herein are not inert, but instead interactwith the elongated VES micelles and associate them together, forinstance connect them into associations (e.g. layers or pseudo-filtercakes) to improve viscosity. In an alternative optional embodiment, theaqueous viscoelastic treating fluid herein has an absence of proppantsthat are a mixture of sintered kaolin clay and amorphous tomicro-crystalline silica, such as those described in U.S. Pat. No. Re.34,371 incorporated by reference herein in its entirety.

The invention will be further described with respect to the followingExamples which are not meant to limit the invention, but rather tofurther illustrate the various embodiments.

EXAMPLES

The results of laboratory tests, as presented in FIGS. 1 and 2, showthat nano-sized clay mineral viscosity enhancers, such asmontmorillonite, may significantly improve the viscosity of VES-gelledaqueous fluids.

FIG. 1 presents a graph of the viscosity of two viscoelastic 13.0 ppg(1.6 kg/liter) CaCl₂/CaBr₂ brine fluids containing 4% VES, measured at250° F. (121° C.) and 100 1/s over time. The fluid represented by theblack curve does not have a viscosity enhancer, and it may be readilyseen that the viscosity diminishes relatively rapidly over time. Theother, gray curve, represents a fluid containing 10 pptg (1.2 kg/m³)montmorillonite nano-sized clay particles. The clay particles are MOClay product, Mineral Colloid MO, a high purity montmorillonite, whichis a product of Southern Clay Products, Inc. The particle size is lessthan 1000 nanometers. It is clear that the fluid with themontmorillonite clay particles generally maintains viscosity at or above200 cP over the test period, demonstrating that these clay particles doenhance viscosity.

FIG. 2 shows a graph of fluid leakoff in milliliters as a function oftime for two viscoelastic 13.0 ppg (1.6 kg/liter) CaCl₂/CaBr₂ brinefluids containing 4% VES, measured at 250° F. (121° C.) and 100 1/s.These fluids have 1.0 gptg GBW-407L (Fish Oil 18:12 product fromBioriginal Food & Science Corporation) internal breaker. Again, thefluid represented by the black curve does not contain a nano-sized claymineral and shows rapid leakoff. The fluid represented by the gray curvecontains 20 pptg (2.4 kg/m³) MO Clay montmorillonite nano-sized clayparticles, and it may be seen that the fluid leakoff is much moregradual.

FIG. 3 is a photograph of a viscous layer of pseudo-filter cake, whichis built from 13.0 ppg (1.6 kg/liter) CaCl₂/CaBr₂ brine fluid containing4% VES, 1 gptg GBW-407L internal breaker and 20 pptg (2.4 kg/m³) MO Clayat 250° F. (121° C.) and 300 psi (2.1 MPa). This photograph demonstratesthat the charges in the platelets of the montmorillonite clay associatewith the VES micelles to build pseudo-filter cake to control fluidleakoff.

FIG. 4 is another photograph of a pseudo-filter cake built on a 400 mDceramic disc from 13.0 ppg (1.6 kg/liter) CaCl₂/CaBr₂ brine fluidcontaining 4% VES, and 20 pptg (2.4 kg/m³) MO Clay at 250° F. (121° C.)and 300 psi (2.1 MPa). This is this the same fluid as that used in theFIG. 3 photograph. This photograph also demonstrates that the charges inthe platelets of the montmorillonite clay associate with the VESmicelles to build pseudo-filter cake to control fluid leakoff, and thatthe viscous pseudo-filter cake clings to the nearly vertical disk.

In the foregoing specification, the invention has been described withreference to specific embodiments thereof, and has been demonstrated aseffective in improving or enhancing viscosity for VES gelled fluids.However, it will be evident that various modifications and changes canbe made thereto without departing from the broader spirit or scope ofthe invention as set forth in the appended claims. Accordingly, thespecification is to be regarded in an illustrative rather than arestrictive sense. For example, specific combinations of brines,viscoelastic surfactants, nano-sized clay mineral viscosity enhancersand other components falling within the claimed parameters, but notspecifically identified or tried in a particular composition, areanticipated to be within the scope of this invention.

The words “comprising” and “comprises” as used throughout the claims isto be interpreted as “including but not limited to”.

The present invention may suitably comprise, consist or consistessentially of the elements disclosed and may be practiced in theabsence of an element not disclosed. For instance, the gelled aqueousviscoelastic treating fluid may consist of or consist essentially of anaqueous base fluid, a viscoelastic surfactant (VES) gelling agent in anamount effective to increase the viscosity of the aqueous base fluid byforming elongated micelles, and a clay mineral (phyllosilicate) particleviscosity enhancer, where the clay mineral particle viscosity enhancerhas an average particle size ranging from about 1 to about 1000nanometers, where the clay mineral particle viscosity enhancer ispresent in an amount effective to improve viscosity of the fluid ascompared with an identical fluid absent the clay particle viscosityenhancer by associating the micelles together in an association,

Alternatively, the aqueous viscoelastic treating fluid may consist of orconsist essentially of a brine aqueous base fluid, a viscoelasticsurfactant (VES) gelling agent in an amount effective to increase theviscosity of the aqueous base fluid by forming elongated micelles, and aphyllosilicate mineral particle viscosity enhancer selected from thegroup consisting of montmorillonites, bentonites, zeolites, kaolinites,smectites, chlorites, illites, mixed layer clays of the foregoing clayminerals, quartz, ceramics, and mixtures thereof, where thephyllosilicate mineral particle viscosity enhancer has an averageparticle size ranging from about 1 to about 1000 nanometers, in anamount effective to improve viscosity of the fluid as compared with anidentical fluid absent the viscosity enhancer, and the phyllosilicatemineral particle viscosity enhancer has an absence of scale resistantproppants and an absence of proppants that are a mixture of kaolin clayand amorphous to micro-crystalline silica.

What is claimed is:
 1. A method for treating a subterranean formationcomprising: injecting a gelled aqueous viscoelastic surfactant treatingfluid through a wellbore and into the subterranean formation, where thegelled aqueous viscoelastic treating fluid comprises: an aqueous basefluid; a viscoelastic surfactant (VES) gelling agent in an amounteffective to increase the viscosity of the aqueous base fluid by formingelongated micelles; and a phyllosilicate mineral particle viscosityenhancer selected from the group consisting of montmorillonites,bentonites, smectites, chlorites, illites, mixed layer clays of theforegoing, and mixtures thereof, where the phyllosilicate mineralparticle viscosity enhancer has an average particle size ranging fromabout 1 to about 1000 nanometers, where the phyllosilicate mineralparticle viscosity enhancer is present in an amount of from about 0.1 toabout 500 pptg (about 0.012 to about 60 kg/m³) based on the totalaqueous viscoelastic treating fluid, where the aqueous viscoelastictreating fluid has an absence of scale resistant proppants; and anabsence of proppants that are a mixture of kaolin clay and amorphous tomicro-crystalline silica; and an absence of added silica prior to theinjecting; and treating the subterranean formation.
 2. The method ofclaim 1 where the phyllosilicate mineral particle viscosity enhancer hasbeen modified to be hydrophobic.
 3. The method of claim 1 where treatingthe subterranean formation is selected from the group consisting of:fracturing the formation under an effective pressure where the aqueousviscoelastic treating fluid further comprises a proppant; packing theformation with gravel where the aqueous viscoelastic treating fluidfurther comprises gravel; stimulating the formation where the aqueousviscoelastic treating fluid further comprises a stimulating agent;completing a well; and controlling fluid loss where the aqueousviscoelastic treating fluid further comprises a component selected fromthe group consisting of a salt, an easily removed solid, and a mixturethereof.
 4. The method of claim 1 where the aqueous viscoelastictreating fluid further comprises at least one internal breaker.
 5. Themethod of claim 1 where for a period of time during the method theaqueous viscoelastic treating fluid is at a temperature of from about70° F. to about 400° F. (about 21 to about 204° C.).
 6. A method fortreating a subterranean formation comprising: injecting the aqueousviscoelastic surfactant treating fluid through a wellbore and into thesubterranean formation, where the aqueous viscoelastic treating fluidcomprises: a brine aqueous base fluid; a viscoelastic surfactant (VES)gelling agent in an amount effective to increase the viscosity of theaqueous base fluid by forming elongated micelles; and a phyllosilicatemineral particle viscosity enhancer selected from the group consistingof montmorillonites, bentonites, smectites, chlorites, illites, mixedlayer clays of the foregoing, and mixtures thereof, where thephyllosilicate mineral particle viscosity enhancer has an averageparticle size ranging from about 1 to about 1000 nanometers, in anamount from about 0.1 to about 500 pptg (about 0.012 to about 60 kg/m³)based on the total aqueous viscoelastic treating fluid, and thephyllosilicate mineral particle viscosity enhancer has an absence ofscale resistant proppants and an absence of proppants that are a mixtureof kaolin clay and amorphous to micro-crystalline silica; where thegelled aqueous viscoelastic treating fluid has an absence of addedsilica prior to the injecting; and treating the subterranean formation.7. The method of claim 6 where treating the subterranean formation isselected from the group consisting of: fracturing the formation under aneffective pressure where the aqueous viscoelastic treating fluid furthercomprises a proppant; packing the formation with gravel where theaqueous viscoelastic treating fluid further comprises gravel;stimulating the formation where the aqueous viscoelastic treating fluidfurther comprises a stimulating agent; completing a well; andcontrolling fluid loss where the aqueous viscoelastic treating fluidfurther comprises a component selected from the group consisting of asalt, an easily removed solid, and a mixture thereof.
 8. The method ofclaim 6 where for a period of time during the method the aqueousviscoelastic treating fluid is at a temperature of from about 70° F. toabout 400° F. (about 21 to about 204° C.).